Throttling boiler for fouling mitigation

ABSTRACT

Methods and systems generate steam for thermal oil recovery, such as a steam assisted gravity drainage (SAGD) operation. Feedwater is first pressurized to a pressure above that desired for steam injection in the SAGD operation before being heated to avoid at least some nucleate boiling. After being throttled, the local boiling regime is beyond the nucleate boiling regime due to the local pressure drop and the enhanced mixing caused by the throttling process. Two-phase liquid may continue through the boiler generating higher quality steam.

PRIOR RELATED APPLICATIONS

This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/771,202 filed 1 Mar. 2013, entitled “THROTTLING BOILER FOR FOULING MITIGATION,” which is incorporated herein in its entirety.

FIELD OF THE INVENTION

The invention relates to methods and systems for generating high pressure steam with minimal or eliminated fouling otherwise resulting largely from boiling nucleation.

BACKGROUND

Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation in which a pair of horizontal wells are drilled into the oil reservoir, one a few meters above the other. High pressure steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to gravity drain into the lower wellbore, where it can be pumped to the surface.

As in all thermal recovery processes, the cost of steam generation is a major contributor to the cost of oil production. Historically, natural gas has been used as a fuel for Canadian oil sands projects, due to the presence of large stranded gas reserves in the oil sands area. However, with the building of natural gas pipelines to outside markets in Canada and the United States, the price of gas has become an important consideration. Other sources of generating heat are under consideration, notably gasification of the heavy fractions of the produced bitumen to produce syngas, using the nearby deposits of coal, or even building nuclear reactors to produce the heat.

Considering oil production volume, and the fact that approximately 3 barrels of water are needed for every barrel of oil, the water requirements for SAGD are immense. In addition to the cost of steam generation, each barrel of oil produced in SAGD is coproduced with 2-5 barrels of water, which then must be separated from the oil, and treated and/or reused. Water treatment facilities further contribute to cost.

In general, the SAGD process requires high quality, high temperature and high pressure steam. For example, the SAGD process may call for 100% quality, 7,000-11,000 kilopascals (kPa) and 285-318° C. temperature steam. In a typical steam/water circuit, boiler feedwater is supplied by a high pressure feed-water pump at an elevated pressure around 13,000 kPa or less, which results in corresponding steam pressure that gradually decreases along the pipeline to aforementioned injection pressures due to the loss in transportation and eventually by choking to the desired injection pressure.

A once-through steam generator (OTSG), for example, generates around 75% to 80% quality steam, which then goes through a series of liquid-steam separators (also called “flash drum”) to increase the low steam quality of OTSG. OTSG is a large, continuous tube type steam generator in which the steam is produced at the outlet of the continuous tube. Feedwater is supplied at one end of the tube having low temperature, and then undergoes heating and boiling as it travels in a single pass along the tube.

Typically, an OTSG comprises a convection section (also called economizer section) and a radiant section. In the convection section, the feedwater is preheated by heat exchange with a hot combustion gas, usually flue gas. In the radiant section, the feedwater/wet steam is heated by the heat radiated from the furnace, resulting in about 80% quality steam, i.e. the weight ratio of water to steam at the outlet of the generator is about 1:4.

A source of large amounts of fresh or brackish water and large water recycling facilities are required in order to create the steam for the SAGD process. Boiler feed-water (BFW) quality is critical because dissolved solids develop scales that are the major cause of boiler failure and efficiency losses. Therefore, the total dissolved solids (TDS) for BFW needs to be controlled under a certain level to prevent or alleviate the scaling issue.

Fouling is the contamination of the heating surface, and the build-up of contaminant eventually decreases the heat-flux and thus the heating efficiency. Therefore, the boiler has to be shut down several times a year to remove the fouling layer and/or repair the tubing. In addition to the repair cost, the downtime increases the cost of the SAGD operation.

Therefore, a need exists for an improved heating/pre-heating scheme that can minimize the fouling issues and reduce the downtime and cost for SAGD operations.

SUMMARY

The present disclosure provides a method of eliminating or minimizing the fouling caused by nucleate boiling and/or transition boiling of the feedwater in a steam generator. The current invention significantly reduces or even eliminates fouling by heating the boiler feedwater at pressures significantly higher than the output steam delivery pressure, thereby maintaining the feedwater in liquid phase before flashing it off to generate steam. The method, therefore, minimizes or eliminates the fouling caused by nucleate boiling in the boiler. This approach can minimize the downtime of the boiler for repairing or removing the fouling, thereby, increasing the operating time.

The disclosure provides a method of preheating feedwater of a steam generator, comprising a) providing feedwater through a steam generator system under sufficient pressure to heat said feedwater and prevent the formation of steam; b) passing said heated feedwater out of said steam generator system to a pressure reducer where said heated feedwater is flashed to steam; and c) conveying said steam into a wellbore for mobilizing oil.

Any suitable valve can be used to flash the heated feedwater to steam, including a throttling valve, fine nozzle or orifice, and the like. Armstrong-Yoshitake Inc., for example, makes the GP-2000R valve, which is a high performance externally piloted throttling back pressure valve for large capacity applications, and they make many additional pressure reducing valves.

As discussed further herein, the pressure-reducing step can be performed before or after the feedwater enters the radiant section, depending on the system configuration, where fouling tends to build up, and other considerations. For feedwater supplied to the boiler's economizer, the pressure-reducing step can be performed before or after the heating step at the radiant section. For feedwater supplied directly to the furnace heater tubes or heat exchanger tubes, the pressure-reducing step is performed after such heating.

The disclosure also provides a steam generator system, comprising the following components in fluid communication: a) a pressurizing element for increasing the pressure of said feedwater; b) an economizer for preheating the feedwater; c) a radiant section for further heating said feedwater from said economizer, and d) a pressure-reducing element for reducing the system pressure positioned as desired to at least minimize fouling. As noted above, the pressure reducing element can be after the preheating, or after the further heating steps. The system can also be combined with a flash vessel or other separator, for separating steam from condensate, and the flash steam can be injected downhole, and condensate rerouted, for example to the economizer section, either as feedwater, or as a heat source for the economizer.

In another embodiment, an improved method of producing oil includes heating feedwater sufficiently to make steam to inject into a wellbore and mobilize oil for production, the improvement comprising heating feedwater under a pressure sufficient to prevent nucleate boiling, rapidly reducing said pressure to make flash steam and injecting said flash steam into a wellbore, thus mobilizing oil for production.

As used herein, “heat flux” is the rate of heat energy transfer through a given surface, in other words, the heat rate per unit area, whereas “critical heat flux” describes the thermal limit of a phenomenon where a phase change occurs during heating, which suddenly decreases the efficiency of heat transfer, thus causing localized overheating of the heating surface.

As used herein, “flash steam” is the name given to the steam formed from hot condensate when the pressure is reduced. Flash steam is no different from normal steam, it is just a convenient name used to explain how the steam is formed. Normal or “live” steam is produced while heating at a boiler, steam generator, or waste heat recovery generator—whereas flash steam occurs when high pressure/high temperature condensate is exposed to a large pressure drop, such as when exiting a steam trap.

High temperature condensate contains high energy that cannot remain in liquid form at a lower pressure because there is more energy than that required to achieve saturated water at the lower pressure. The result is that some of the excess energy causes a percentage of the condensate to flash.

The percentage of flash steam generated (flash steam ratio) can be calculated from:

Flash%=(Hf1−Hf2)/Hfg2*100

where hf1=Specific Enthalpy of Saturated Water at Inlet, hf2=Specific Enthalpy of Saturated Water at Outlet and hfg2=Latent Heat of Saturated Steam at Outlet. This assumes no energy transfer to the surroundings (adiabatic).

As used herein, “economizer” means the devices for reducing energy consumption in a steam-generating operation by preheating feedwater. Typically, an economizer is in the form of a heat exchanger where the thermal energy is transferred from a high temperature fluid (e.g., steam condensate, flue gas or other waste heat source) to the feedwater such that less energy is required to vaporize it. Economizers are mechanical devices intended to reduce energy consumption or to perform another useful function such as preheating a fluid. They are fitted to a boiler and save energy by using e.g., the exhaust gases from the boiler or other hot plant fluids to preheat the cold feedwater. It has been reported that approximately 35 to 50% of the total absorbed heat in OTSG is transferred in the economizer.

As used herein, a “flash steam recovery vessel” or “flash vessel” is that vessel used to separate flash steam from condensate. After condensate and flash steam enter the flash vessel, the condensate falls by gravity to the base of the vessel, from where it is drained, via a float trap, usually to a vented receiver from where it can be pumped. The flash steam in the vessel is piped from the top of the vessel to any appropriate pressure steam equipment or injected directly into the wellbore.

As used herein, “radiant section” means the section in a steam generator where the heating of feedwater is primarily achieved by radiant heat transfer.

The use of the word “a” or “an” when used in conjunction with the term “comprising” in the claims or the specification means one or more than one, unless the context dictates otherwise.

The term “about” means the stated value plus or minus the margin of error of measurement or plus or minus 10% if no method of measurement is indicated.

The use of the term “or” in the claims is used to mean “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive.

The terms “comprise”, “have”, “include” and “contain” (and their variants) are open-ended linking verbs and allow the addition of other elements when used in a claim.

The phrase “consisting of” is closed, and excludes all additional elements.

The phrase “consisting essentially of” excludes additional material elements, but allows the inclusions of non-material elements that do not substantially change the nature of the invention.

The following abbreviations are used herein:

ABBREVIATION TERM ATM Atmosphere CPF Central processing facility OTSG Once-through steam generator SAGD Steam-assisted gravity drainage Ts Saturation temperature

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates one embodiment of the disclosure, where the pressurization of feedwater occurs prior to entering the economizer, and wherein the pressure-reducing step occurs within the economizer (but after preheating).

FIG. 2 illustrates another embodiment of the disclosure, where the feedwater is pressurized prior to entering the economizer, and wherein the depressurization step occurs outside the economizer.

FIG. 3 illustrates another embodiment of the disclosure, where the pressurization of feedwater occurs prior to entering the economizer, and the flash steam occurs after both the preheating and the further heating in the radiant section.

FIG. 4 illustrates a variation wherein a different heating system is used, but feedwater is still pressurized to prevent nucleate boiling, and the very hot water is flashed to steam after exiting the heating unit.

FIGS. 5 and 6 are pressure-enthalpy diagrams of embodiments illustrated in FIGS. 1-4.

DETAILED DESCRIPTION

The disclosure provides a novel method for generating steam with minimized or eliminated fouling caused by nucleate boiling and/or transition boiling. The disclosure also provides a novel system for implementing the method. It is believed that by using the method and system of the methods described herein, fouling in the steam generator due to nucleate boiling can be greatly reduced or eliminated, thereby reducing the operational cost and downtime for repairing and maintaining the steam generator.

Methods and systems generate steam for thermal oil recovery, such as a steam assisted gravity drainage (SAGD) operation. Feedwater is first pressurized to a pressure above that desired for steam injection in the SAGD operation before being heated to avoid at least some nucleate boiling. After being throttled, the local boiling regime is beyond the nucleate boiling regime due to the local pressure drop and the enhanced mixing caused by the throttling process. Two-phase liquid may continue through the boiler generating higher quality steam.

Nucleate boiling is considered one of the main reasons for fouling in heat transfer tubes. Nucleate boiling is characterized by the growth of bubbles on a heated surface, which rise from discrete points on a surface, whose temperature is only slightly above the liquid temperature. As the bubble enters the bulk flow, the bubble condenses back to liquid. In general, the number of nucleation sites are increased by an increasing surface temperature and by irregular surfaces of the boiling vessel.

Nucleate boiling takes place when the surface temperature is hotter than the saturated fluid temperature by a certain amount but where the heat flux is below the critical heat flux. The critical heat flux defines a maximum heat flux between nucleate boiling and transition boiling. For example, nucleate boiling for water may occur when the surface temperature is higher than the saturation temperature (T_(s)) by between 4° C. to 30° C.

In general, an improved method of generating steam for SAGD and other heavy oil production uses is provided, wherein feedwater is pressurized, to e.g., about 14,000 kilopascals (kPa), thus minimizing or eliminating nucleate boiling. The pressurized water is heated while maintaining a liquid phase, and then later flashed to steam, which can be used downhole. According to the phase diagram of water, the pressurized feedwater can be heated in liquid phase without vaporizing, and the absorbed enthalpy will transform the water into steam once the heated feedwater is flashed off. The flash-off process involves little or no boiling, thereby reducing the fouling. The method can be combined with an economizer or heat exchange system and the feedwater can be pressurized either before the heat exchanger or afterwards, as convenient or as dictated by the existing tendencies towards fouling.

A system for generating steam is also provided, comprising a pressurizing element for increasing the pressure of the system, an optional economizer for preheating feedwater, a radiant section for heating the feedwater from the economizer, and a pressure-reducing element for reducing the system pressure and producing flash steam. In this system, the pressurizing element increases the pressure of the system before the feedwater is supplied to the economizer and/or radiant section. Of course, all of the elements are in fluidic connection, such that pressure and fluid can travel from one part of the system to another.

A flash vessel can be used to separate flash steam from condensate, which can be routed back to e.g., the economizer for preheating feedwater.

In preferred embodiments, the pressurizing element is upstream of the economizer, but not necessarily so. The economizer, if used, is preferably upstream of the radiant section, which is upstream of the pressure reducing valve, which is upstream of the flash vessel, and the condensate from the flash vessel preferably routes back to the pressurizing element or economizer. Alternatively, the pressure reducing valve can be upstream of the radiant section if there is limited or no tendency to fouling in the radiant section.

The pressurizing element can be any device, such as a pump, known in the field to increase system pressure. The pressure-reducing element can be any device known in the field to reduce system pressure. Non-limiting examples include orifices, valves, or a combination thereof.

The system pressure is increased to the extent that the feedwater can remain in liquid phase without boiling when being heated. Also, the system pressure may only be increased to the extent commercially feasible without incurring additional cost to replace the piping to withstand higher pressure. In one embodiment, the system pressure is increased to at least 20,000 kPa, at least 14,000 kPa or at least 10,000 kPa. Use of solvents and/or generation of the steam at a pad for injection instead of a central processing facility may enable lower pressure steam needs such that the increase of the system pressure may be to only at least 5000 kPa or at least 3500 kPa.

The placement of the pressure-reducing element in the system may vary, depending on where the fouling is to be reduced. For example, if fouling is serious in the economizer, but not in other parts of the OTSG, then the pressure-reducing element can be installed right after where the feedwater exits the economizer. If, on the other hand, the fouling is to be reduced throughout the OTSG, the pressure-reducing element can be installed after where the feedwater exits the radiant section, thereby maintaining the feedwater in liquid phase to avoid nucleate boiling throughout. In some embodiments, the pressure-reducing element accommodates pigging and may be located to enable and/or not interfere with other maintenance and operational needs.

The system pressure is reduced to the extent that the feedwater can rapidly convert from liquid to steam after being preheated or heated. This rapid phase conversion involves little or no boiling, and therefore can minimize the fouling associated with nucleate boiling. In one embodiment, the system pressure is reduced by at least 6500 kPa or at least 3500 kPa due to the pressure-reducing element.

FIG. 1 illustrates an embodiment of the present disclosure. Shown therein is a configuration of a steam generator, wherein feedwater is supplied first to an economizer section 101 for pre-heating, followed by a radiant section 102 to generate the steam of specified quality. A separator 103 then separates the steam 104 from the un-vaporized water 105, where the steam is supplied to SAGD operations and the hot water is discharged or recycled for further use.

Prior to being supplied to the economizer 102, the feedwater is first pressurized by a pressurizing means 107. The pressurizing means can be any mechanism that effectively pressurizes the system such that the boiling point of water is elevated. Here the pressurizing means 107 is a pump for supplying water under pressurized condition.

The pressurized feedwater 108 is then supplied to the economizer section 101, where the feedwater can be pre-heated by the exhausted gases of the boiler, such as CO₂, through heat exchange. Because of the elevated pressure of the system, the feedwater will not be vaporized at this point, but instead remains in liquid phase. One or more pressure reducers 106 can be installed in the pipeline so as to reduce the system pressure before the water enters the radiant section 102, where the feedwater is further heated to produce the remaining steam. The pressure reducer can be any known mechanism that reduces the pressure, for example, orifices inserts, valves, etc.

FIG. 5 shows a pressure-enthalpy steam diagram for water. The upper left region is the liquid region where all water remains liquid. The upper right is the supercritical region where distinct liquid and gas phases do not exist. As the critical point is approached, the properties of the gas and liquid phases approach one another, resulting in only one phase at the critical point: a homogeneous supercritical fluid. The lower left is the saturated region, where liquid and vapor water co-exists. The lower right is the vapor region where all water becomes vaporized. In a traditional steam generator, the water is heated along the line from point 1 to 2, where nucleate boiling occurs around the intersection between the 1-2 line and the boundary between liquid and saturated water (point 6). As discussed above, nucleate boiling is one major reason resulting in fouling, and is preferably avoided.

The methods described herein with reference to FIG. 1, in contrast, take a different route. From point 1 in FIG. 5, the system is first pressurized to point 3, where the pressure is significantly higher than one atmosphere, and preferably higher than the highest pressure of the saturated region to the extent commercially feasible, and more preferably at least 14,000 kPa. The feedwater under pressurized condition is then pre-heated at this pressure along the line between points 3 and 4. The pressure of the system is then reduced (e.g., to between 5000 kPa and 13,000 kPa) after passing through the orifices, thus reaching point 5. At this stage, there could be a mixture of steam and liquid water, which is then heated at the radiant section 102 as depicted by the line from point 5 to point 2. As such, the majority of nucleation boiling, particularly corresponding to the path from point 1 to point 5, is avoided.

In the conventional non-pressurized condition, continuous heat is provided to the heat exchange tubes, where slow (e.g., residence times around one minute) and continuous boiling takes place, and this is believed to be the main reason of fouling. In this example, because the enthalpy of the feedwater is sufficiently high and would have vaporized the feedwater under lower pressure, the reduction of the system pressure at the pressure reducers 106 rapidly converts the feedwater from liquid to vapor, and therefore involves little or no boiling of the water. This vaporization approach in turn reduces the chance of fouling.

FIG. 2 shows a variation of the embodiment illustrated in FIG. 1. The basic configuration of the steam generator still includes the economizer section 201, the radiant section 202 and the separator 203. The feedwater is still supplied with the system pressurized by a pump 207 prior to entering the economizer 201. The only difference between FIG. 1 and FIG. 2 is that in this embodiment, the pre-heated water circulates outside the economizer section 201 and the pressure is reduced at this point. This embodiment shows that the inventive method can be applied to different OTSG configurations.

FIG. 3 illustrates another embodiment that still includes an economizer section 302 and a radiant section 303. The pressurized feedwater 308 is supplied from a pump 307 to the economizer 302 for pre-heating, followed by further heating in the radiant section 303. The heated water then goes through a pressure reducer 310 where flash steam is produced before entering the separator 304. The separator 304 then separates the high pressure steam 305 from the residual water 306 (if any), which will e.g., be directed to heat exchanger 309 to further pre-heat the pressurized feedwater 308 before being discharged or recycled.

FIG. 6 shows a pressure-enthalpy diagram for this embodiment depicted in FIG. 3. Similar to FIG. 5, the path from point 1 to 3 corresponds to the pressurizing step by the pump 307 in FIG. 3. However, as seen in FIG. 3, the pressure-reducing step is not performed until after all the heating steps, including preheating at the economizer and heating at the furnace, are completed, hence the end point 2 in this figure coincides with the reduced-pressure point 5 in FIG. 5. It is to be noted that the pressurizing-heating path of points 1-3-4-5-2 effectively bypasses the boiling nucleation, thereby reducing the fouling.

FIG. 4 is another embodiment of the method utilizing a heat exchanger 501 with high pressure water heating tubes. In this embodiment, the heat exchanger 501 for heating water has a hot fluid inlet 502 for introducing a high temperature fluid, preferably having high thermal capacity, and a hot fluid exit 503 for discharging the hot fluid after heat exchange. The high thermal capacity also helps the efficiency of the heat exchange. The system is first pressured by pump 507, and feedwater 508 is then supplied to the heat exchanger 501 for heating to generate a very hot water. The hot fluid preferably has a temperature significantly higher than the feedwater 508 such that the transferred heat would be sufficient to vaporize the feedwater 508 without the additional pressure that maintains the feedwater 508 in liquid phase. A pressure reducer, in this case a valve 510, reduces the pressure of the water for vaporization, which then enters the separator 504. The high pressure steam 505 is then supplied to SAGD operations, whereas the water 506 can be introduced to another heat recovery device 509 to pre-heat the pressurized feedwater 508.

Although the steam is generated by a different mechanism, operation of the heat exchanger 501 in FIG. 4 follows a similar path in the pressure-enthalpy diagram illustrated in FIG. 6, thereby avoiding boiling nucleation and minimizing fouling in the water pipelines.

For the embodiments illustrated in FIG. 3-4, the heated high pressure feedwater flashes off at either the central processing facility or well pad operating pressure, depending on the steam generation location. As implemented, in addition to the costs saved, this method can reduce the pipe rack capital of the surface facility because now only water lines need to go to the well pads instead of steam lines since steam may be produced on site (i.e. at the well pads) and not before.

Based on the above illustrations, it is clearly shown that the methods and systems herein described pressurize the feedwater before it enters the heating mechanism and thereby avoids the nucleate boiling phase that directly contributes to fouling. Downtime for pigging/repairing the boiler and pipes can be greatly reduced, therefore cutting down the operation cost.

The following documents are incorporated by reference in their entirety:

Gwak et al., A Review of Steam Generation for In-Situ Oil Sands Projects, Geosystem Engineering, 13(3), 111-118 (September 2010). 

What is claimed is:
 1. A method of producing steam for oil production, comprising: a) providing feedwater through a steam generator system under sufficient pressure to heat said feedwater and prevent formation of steam in an output of heated feedwater; b) passing said heated feedwater to a pressure reducer where said heated feedwater is flashed to steam; and c) conveying said steam into a wellbore for mobilizing oil.
 2. The method of claim 1, wherein the steam generator is a once-through steam generator.
 3. The method of claim 1, wherein the feedwater in step a) is pressurized to at least 14,000 kilopascals.
 4. The method of claim 1, wherein the feedwater in step a) is pressurized to at least 20,000 kilopascals.
 5. The method of claim 1, wherein the pressure reduction in step b) decreases pressure by at least 3500 kilopascals.
 6. The method of claim 1, wherein the pressure reduction in step b) decreases pressure by at least 6500 kilopascals.
 7. The method of claim 1, wherein said feedwater in step b) is pressurized by a pump.
 8. A steam generator system for oil production, comprising: a) an economizer for preheating feedwater; b) a radiant section for heating said feedwater from said economizer; c) a pressurizing element for increasing the pressure of said system enough to prevent nucleate boiling of the feedwater at least within the economizer; d) a pressure-reducing element for reducing the pressure and producing flash steam; and e) an injection assembly for injecting the flash steam into an oil reservoir, wherein elements a though e are fluidly connected.
 9. The steam generator system of claim 8, further comprising a flash vessel.
 10. The steam generator system of claim 8, wherein said pressure-reducing element is at least one of an orifice and a throttling valve.
 11. The steam generator system of claim 8, wherein said pressure-reducing element reduces the system pressure of said feedwater from said radiant section.
 12. The steam generator system of claim 8, wherein said pressure-reducing element reduces the system pressure from said economizer.
 13. The steam generator system of claim 8, wherein said steam generator system is a once-through steam generator.
 14. The steam generator system of claim 8, wherein said pressurizing element is a pump.
 15. The steam generator system of claim 8, wherein said pressurizing element increases the pressure of said feedwater to at least 14,000 kilopascals.
 16. The steam generator system of claim 8, wherein said pressurizing element increases the pressure of said feedwater to at least 20,000 kilopascals.
 17. The steam generator system of claim 8, wherein said pressure-reducing element reduces the pressure by at least 3500 kilopascals.
 18. The steam generator system of claim 8, wherein said pressure-reducing element reduces the pressure by at least 6500 kilopascals.
 19. An improved method of producing oil, the method comprising generating steam to inject into a wellbore and mobilize oil for production, the improvement comprising heating feedwater under a pressure sufficient to prevent nucleate boiling, reducing said pressure to make flash steam prior to any nucleate boiling of the feedwater and injecting said flash steam into a wellbore to mobilize the oil for production. 